ML20217E867
| ML20217E867 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 03/27/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20217E836 | List: |
| References | |
| 50-454-98-04, 50-454-98-4, 50-455-98-04, 50-455-98-4, NUDOCS 9803310189 | |
| Download: ML20217E867 (37) | |
See also: IR 05000454/1998004
Text
F ~
i
\\
f
U.S. NUCLEAR REGULATORY COMMISSION
i
REGION 111
i
l
Docket Nos:
50-454,50-455
License Nos:
Report Nos:
50-454/98004(DRS); 50-455/98004(DRS)
Licensee:
Commonwealth Edison Company
Facility:
Byron Nuclear Plant, Units 1 and 2
Location:
4450 N. German Church Road
Byron,IL 61010
Dates:
January 20,1998 through February 10,1998
Inspectors:
Z. Falevits, Reactor Engineer, Team Leader
T. Tella, Reactor Engineer
D. Schrum, Reactor Engineer
T. Ippolito, Scientech Contractor
C. Jones, Scientech Contractor
Approved by:
John Jacobson, Chief
Lead Engineers Branch
Division of Reactor Safety
)
l
<
l
t
!
l
9803310189 980327
ADGCp 05000454
G
_
a
I
EXECUTIVE SUMMARY
I
i
Byron Nuclear Plant, Units 1 and 2
l
NRC Inspection Report 50454/98004(DRS); 50-455/98004(DRS).
Engineerina
i
The AF battery rack modification was not subjected to design control measures
.
commensurate with those applied to the original design and part of the modification was
not completed in the field but the modification was closed out. Two violations were
identified in this area. (Section E1.2.1)
The inspectors determined that the licensee failed to establish an effective process for
.
independent inspection and verification of modification activities affecting quality, such
as field installations of safety related exempt changes. A violation was identified in this
area. (Sect'on E1.3)
The emergency diesel generator (EDG) system engineer's interface with the Braidwood
.
EDG system engineer during evaluations for previously untested EDG switches and the
subsequent identification of deficient control wiring in the EDG control panel was
considered very positive. (Section E1.3)
i
Overall, safety related modification packages reviewed by the team were of good
j
.
technical quality. However, the team identified concerns relative to modification testing
i
and modification package closure. An example of a violation was identified in this area.
(Section E1.4)
The licensee failed to develop an instrument out-of-tolerance process to address
.
repetitive out-of-tolerance problems. A corporate procedure had not been implemented.
An example of a violation was identified in this area. (Section E2.1)
The design and system engineers directly involved with the team in the discussions of
.
technical issues were generally found to be qualified and experienced in their respective
positions. Further, the engineers demonstrated pride and ownership of their respective
areas of responsibilities. (Sections E2.4 and E4.1)
The pre-fire plans were not maintained to meet the criteria of 10 CFR 50, Appendix R,
.
and the commitments of NRC branch technical position BTP CMEB 9.5-1, Appendix A,in
that the drawings had not been updated for more than 10 years. A violation was identified
in this area. (Section F3.1)
2
i
\\
l
The licensee failed to conduct annual physical exams whose results were used to
.
assess the fire brigade for unrestricted activity. A violation was identified in this area.
l
(Section F5.1)
1
(
The audits / assessments conducted by SQV and outside auditors were done well and
J
.
I
included several significant findings, however, weaknesses in follow up activities were
identified. (Section E7.1)
{
The engineering self assessments reviewed by the team needed improvement in quality,
.
particularly in design engineering. More guidance was needed for follow up on the
findings identified during these self assessments. (Section E7.2)
,
!
i
3
,
I
l
lli. Engineering
E1
Conduct of Engineering (IP 37550)
The team selected the following systems for a more detailed design review during the
inspection: Auxiliary feedwater (AF), Auxiliary building ventilation (VA), and Switchyard
(SY).
E1.1
Generic Letter 96-01 "Testino of Safety Related Logic Circuits"
a.
Insoection Scoce
Prior to issuing Generic Letter (GL) 96-01," Testing of Safety Related Logic Circuits,"
dated January 10,1996, the NRC has documented, in various Information Notices, a
significant number of instances involving problems with logic testing of safety-related
circuits. The team examined Byron's actions taken to address concerns documented in
b.
Observations and Findings
The NRC issued GL 96-01 to: (1) notify addressees about problems with testing of-
safety-related logic circuits, (2) request that all addressees implement the actions
described in the GL, and (3) require that all addressees submit a written response to the
generic letter regarding implementation of the requested actions.
The GL requested that licensee's compare electrical schematic drawings and logic
diagrams for the reactor protection system, emergency diesel generator (EDG) load
shedding and sequencing, and actuation logic for the engineered safety features
systems against plant surveillance test procedures. This was to be done to ensure that
all portions of the logic circuitry, including the parallel logic, interlocks, bypasses and
inhibit circuits, are adequately covered in the surveillance procedures to fulfill the
technical specification (TS) requirements,
in a letter to the NRC dated April 19,1996, the licensee committed to implement the
actions requested by GL 96-01 at Byron Units 1 and 2, following Byron Unit 1 refueling
outage B1R08 which was being completed in February 1998. During review of
licensee's actions to address this issue, the team noted that Duke Engineering initial
review (completed January 14,1998) of Byron Units 1 and 0 TS surveillance procedures
and electrical drawings identified approximately 250 untested contacts in safety-related
circuits. The review of Unit 2 was expected to be completed in February 1998.
The team determined that there was no plan to promptly evaluate and address the
untested contacts. The licensee informed the team that, due to an event that occurred
at another pressurized water reactor (PWR) in June 1997, which involved inadequate
testing of interlock circuitry for the P-11 Permissive, Byron engineering was in the
process of informing the NRC that resolution of this issue was being extended to the
end of 1998. Following concerns raised by the team regarding prompt resolution of the
l
Duke Engineering findings, the licensee informed the team that the untested contacts
l
4
s
\\
j
i
l
would be promptly evaluated and prioritized as to their safety significance and tested in
f
a timely manner. The team also discussed this issue with NRR staff involved with GL 96-01 to ensure that this issue was being addressed uniformly.
I
In a related matter, problem identification form (PlF) B1998-00525, dated February 2,
)
1998, documented that a series of breaker interlock contacts used in Units 1 and 2
l
safety injection (SI) automatic actuation logic circuitry have never been tested. These
l
circuits were designed to automatically actuate following receipt of a Si actuation signal,
while both Units 1 and 2 are in modes 1-4 and the engineered safety feature interunit
crosstie breakers are closed (e.g. bus 141 to bus 241). The crosstie configuration is
j
used during station auxiliary transformer maintenance, planned crosstie evolution or
i
restoration from the EDG to the alternate offsite source. Failure of one of the untested
I
contacts to close while the buses were crosstied and an SI signal was present would
result in the automatic load sequencing not occurring. The emergency core cooling
system equipment would not have started automatically as designed, but could be
started manually.
j
i
c.
Conclusions
i
The licensee had committed to implement the actions requested by GL 96-01 at Byron
Units 1 and 2, following Byron Unit 1 refueling outage B1R08 which ended in
February 1998. The team was concerned that there was no plan to promptly evaluate
and address approximately 250 untested contacts in safety-related circuits (identified by
the licensee since April 1996 and reported in January 1998). The licensee informed the
j
team that the potentially untested contacts would be promptly evaluated and prioritized
j
as to their safety significance and tested in a timely manner, in a related matter, PlF
B1998-00525, dated February 2,1998, documented that a series of breaker interlock
contacts used in Units 1 and 2 Si automatic sctuation logic circuitry have never been
tested.
This item is considered Unresolved pending licensee action to address the untested
contacts, issuance of the LER for the February 2,1998 finding and NRC review of
licensee actions (50-454/455/98004-01(DRS)).
E1.2 Review of Modifications and Design Changes
The team examined 18 mechanical, electrical and instrumentation and control
permanent modifications in various stages of implementation. The modification
packages generally documented the work to be done and the post-modification testing
requirements. The modification packages reviewed clearly described the proposed
design changes and justification for the changes and contained 10 CFR 50.59 safety
evaluations. The team also reviewed calculations made in support of the design
changes. The team reviewed selected set point / scaling change requests (SSCRs),
through which some of these design changes were implemented. In general, the
modification packages contained the required design documentation, reviews, and
approvals. However, the inspectors identified concerns in several areas examined as
noted below:
5
l
$
\\
E1.2.1 Incomotete Modification to the AF Battery Rack
a.
Insoection Scoce
i
The team evaluated seismic calculations for design change package (DCP) #9600148.
b.
Observations and Findings
DCP #9600148, " Modify the Mounting Detail for the AF Diesel Racks No.1 AFO1EA-B &
1 AF01EB-B," dated May 1996, reduced the number of anchors and bolts holding the AF
Diesel Battery rack to the floor from 32 to 8 for two existing racks.
(1)
10 CFR Part 50, Appendix B, Criterion lli states, in part, that design control
measures shall be provided for verifying or checking the adequacy of design,
and that design changes, including field changes, be subjected to design control
measures commensurate with those applied to the original design.
The team had concerns that seismic bolting spacing problems had not been
adequately incorporated into the seismic calculations for DCP #9600148. The
seismic calculation only identified that there was only one spacing problem
between the bolts. Field change request (FCR) #960062, dated June 7,1996, to
!
the DCP, identified that five bolts had spacing problems that required evaluation
j
to determine if the seismic analysis was still adequate. The licensee stated that
the seismic analysis bounded the worst case seismic situations, so that
additional seismic evaluations were not necessary. However, the team identified
that the seismic analysis was not accurate in that it specifically stated that only
one spacing problem existed with this DCP.
(2)
10 CFR Part 50, Appendix B, Criterion XVI states, in part, that measures shall be
established to assure that conditions adverse to quality are promptly identified
and corrected. In the case of significant conditions adverse to quality, the
measures shall assure that the cause of the condition is determined and
corrective action taken to preclude repetition.
On February 26,1998, the team conveyed the above seismic bolting concerns to
the licensee with a request for a walkdown to validate the distances between
'
bolts. The licensee discovered during the walkdown that the modification had
not been field completed. The modification for battery rack #1 AF01EA-B was
completed. However, the modification for the battery rack #1 AF01EB-B was not
implemented in the field and still contained 16 bolts. The design engineer could
'
not explain why the modification had not been completed in the field. In addition,
the design engineer stated that there was no requirement for design engineers to
Wdikdown completed design changes. The failure to walkdown completed
design changes was considered a program weakness. PIF #B1998-00952 was
issued on February 27,1998, to evaluate this plant problem.
t
6
'
l
l
s
i
This modification had been originally initiated as a result of a bolt failure on
r
battery rack #1 AF01EA-B during torquing, which was attributed to corrosion. As
a precaution the licensee decided to remove all 32 expansion anchors for battery
racks 1 AFO1EA-B and 1 AF01EB-B along with the 1/4" plates they were attached
to and replace them with new plates and anchors.
l
The DCP was signed as complete by the maintenance staff. Following NRC
questions, the licensee conducted an investigation of the maintenance staff's
decision to not complete this DCP. The DCP did not contain an option to only
complete one-half of the DCP. The system engineer stated that he had been
j
consulted for the cancellation of this modification. Maintenance sta'f's difficulty
in performing the first part of modification and the low amount of corrosion on
Rack #1 AF01EB-B were the reasons given for permission to cancel the DCP.
However, there was no documented evidence of the engineer's evaluation for
making these decisions.
The decision to not complete the DCP allowed a potentially degraded condition
i
to exist unevaluated since June 7,1996. Battery Rack #1AF01EB-B had not
been removed to evaluate the condition of the bolts and anchors. In addition,
'
the failure to complete this DCP resulted in the as-built design drawings and the
,
seismic calculations to not match the design of the plant for the AF battery racks.
'
The licensee stated that the #1 AFO1EB-B Rack would not be modified based on
the design margin of the bolts and anchors. In addition, the as-built drawings
and seismic evaluation would be changed to reflect plant conditions. However,
no written evaluation would be performed.
(3)
In a related issue, Byron inspection Report 50-454/455/95011, dated
,
January 29,1996, documented that on December 5,1995, the NRC identified
that terminals 8 and 11 on the same AF Pump 1B battery (1 AF01EB-B)
contained rust. This was apparently due to water from a service water valve
packing leak over the batteries. The water from this leak also covered the floor
by the AF battery rack bolts and anchors.
c.
Conclusions
On February 4,1998, the team identified that a field change performed on June 7,1996,
was not subjected to design control measures commensurate with those applied to the
i
original design. In addition, a AF battery rack was not installed as required by DCP
l
- 9600148 resulting in as-built drawings and seismic calculations that did not match the
plant design. This is a violation of 10 CFR Part 50, Appendix B, Criterion lli
(50-454/455/98004-02(DRS)).
On February 26,1998, the team identified that corrective actions were not prompt for a
degraded condition for the bolts and anchors for the AF battery rack. DCP #9600148
issued to correct this condition had not been completed since May 15,1996. This is an
1
example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI
(50-454/455/98004-03a(DRS)).
7
i
!
I
i
1
The team concluded that not having a requirement to walkdown completed DCPs
contributed to the above failures.
E1.3 Lack of Indeoendent Verification Process for Exemot Change (modification) installations
a.
Insoection Scoce
The team assesseli the licensee's corrective action and self assessment process. The
team examined the underlying circumstances asrociated with PIF B1997-01549, dated
December 29,1997. This PIF documented a wiring discrepancy identified by the
.
system engineer in the EDG control cabinet.
j
b.
Observations and Findings
PlF B1997-01549, dated December 29,1997, documented a wiring discrepancy
identified by the EDG system engineer in EDG panel 1PLO8J (a jumper that should have
been removed was left installed in the field). The discrepancy was identified during
testing conoucted using special test procedure SPP 97-033. The miswiring could have
resulted in the loss of 1B EDG during a fire.
The team reviewed the associated EDG schematic and wiring diagrams and interviewed
the system engineer. During the interview, the team noted that a second wiring
discrepancy between the drawings and the field installed EDG wiring was also identified
during testing by the system engineer. A jumper that should have been installed in EDG
j
panel 1PLO8J was missing in the field. The system engineer promptly issued PlF
B1998-00576 on February 4,1998, to document this discrepancy.
The team determined that the particular wiring discrepancies identified in the PlFs
)
occurred in May 1996, during the installation of exempt change (EC) DCP 9500185.
The DCP was initiated as part of Thermo-Leg resolution to meet " Appendix R" safe
shutdown requirements. The modification was to resolve inadequate fire separation
issue with Normal Supply 2 (PS-2). The control power for each EDG was originally
provided by two separate DC feeds; Normal Supply 1 (PS-1) and Normal Supply 2
(PS-2). During a loss of offsite power (LOOP), the EDG is required to start and run
assuming a fire disabled Normal PS-2. The EC DCP 9500185 was designed to repower
some critical components from Normal PS-2 to Normal PS-1 so that the EDG could start
and run with only Normal PS-1 available. The modification would ensure that fire in
Zones 5.4-1 and 11.6-0 would not damage cables of Normal PS-2 power feed of both
EDG 1 A and 1B and disable functions which are essential for starting of both EDG 1 A
and 18.
The team noted that the electrical maintenance technician that installed the field wiring
design changes may have made the wiring errors (could have removed tha wrong
jumper), and as a result, cross tied the two EDG 125V de control power supplies (PS-1
l
and PS-2) which must be isolated from each other. The licensee corrected the wiring
errors using
8
s
\\
work request (WR) 970137338. The same design change was implemented on EDGs
1 A,2A and 28. The licensee inspected the changed wiring on the other three EDGs
and found them to conform to the design drawings.
The 50.59 safety evaluation performed for EC DCP 9500185 stated, in section 5, that
the change did not introduce any new failure modes and that repowering connection
changes would be done to internal wiring of the panels in a manner similar to existing
terminations. It further stated that all components would be available to do their
required function; and that all necessary testing would be performed to verify that all
{
critical functions remained unchanged as well as intended changes for design functions
j
as required without any detrimental effect. Furthermore, section 7.c. stated, changes
would be tested prior to turnover to operation for intended function and to verify that no
other malfunction was created as a result of the wiring changes. Therefore, the safety
evaluation conclusions that the probability of the malfunction of safety related equipment
was not increased. The team noted that as a result of the miswiring, the statements and
assumptions made in the 50.59 safety evaluation were incorrect.
,
The team performed a field, cursory sample inspection, of EDG 1 A control panel
1PLO7J using the electrical wiring and schematic diagrams. Several wiring labeling
discrepancies were identified; however, the number of wires on the terminal appeared to
conform to the number delineated on the wiring drawings. The licensee issued PlF
B1998-00606 on February 8,1998, to correct the labeling errors and verify that the field
wiring was indeed correct.
The team also requested that the licensee perform a field wiring inspection of all four
EDG local panels to determine if other wiring discrepancies existed due to the lack of
independent verification process The licensee inspected the panels (by mostly
comparing the number of wires terminated at each terminal) and identified wiring
drawings and labeling discrepancies. PlFs B1998-00875 and B1998-00876 were issued
on February 20,1998, to address the findings.
Procedure NSWP-E-02, Exhibit F, dated May 13,1996, was used to implement WR
950047014-01. The inspectors noted that the miswiring of #53 relay contacts M2 and
M3 in panel 1 PLO8J was performed by the installer without quality control (OC) overview
or other independent verification done. The work instructions for the WR 950047014-01
were written by the licensee using nuclear station work procedure NSWP-E-02,
" Electrical Cable Termination and Inspection," Revision 4. This procedure did not
require the use of independent verification of internal wiring changes. In addition, Byron
administrative procedure BAP 1099-3, "QC Field Inspections," Revision 3, did not
require 100% inspection of safety related exempt change installations.
The team requested that the licensee generate a PlF and nuclear tracking system (NTS)
items computer list using the keywords " wiring" and " configuration control", The list
generated showed that at least 40 PIFs and/or NTS items were issued in 1996 and 1997
to document and track various field wiring deficiencies. The team was concerned that
with this large a number
9
o
4
of wiring discrepancies, no root cause analysis or trending analysis was initiated. The
licensee subsequently initiated PIF B1998-00622 on February 6,1998, to determine if
,
l
an adverse trend regarding wiring discrepancies existed at Byron.
The EC DCP specified construction modification and operability testing. The
i
construction testing ECPT #19 required, in part, that operational analysis department
(OAD) verify that the revised connections were done per schematics and wiring changes
in the ECN. The modification testing required, in part, simulation of Normal PS-2 loss of
l
power. The modification testing performed following installation of EC DCP 9500185
l
failed to identify the wiring discrepancies and found EDG 1B fully operable.
The team closely examined the testing performed following the EC installation. The
team noted that the licensee had established six barriers for post-modification testing to
enswe that installed modifications were tested successfully and that the equipment was
installed as designed / intended. The barriers were: (1) the worker using the " STAR" and
"QW" principles; (2) independent verification; (3) QC overview; (4) construction test
l
ECTP #19 whose purpose was to verify wiring continuity; (5) post-modification testing,
performed to ensure the design intent of the modification was satisfied; and (6) the
operability testing, typically the TS surveillance. It was apparent to the team that none
of the six established barriers prevented or identified the miswiring errors.
j
1
The team concluded that the licensee's process for exempt change (modification)
installation was inadequate. Specifically, the team identified that there was no
requirement in place to perform independent verifications by electrical maintenance
craft, engineering staff or QC in order to verify that all safety-related wiring installations
performed via the exempt change process conformed to the requirements of the design
change documents.
,
'
On the positive side, the team noted that the EDG system engineer was proactive in
contacting the Braidwood EDG system engineer, in initiating the special test to test the
untested switches and in identifying the wiring errors.
I
c.
ConclusiQns
The team concluded that the licensee's process for independent verifications of exempt
change (modification) installations was inadequate. Specifically, the team identified that
there was no requirement in place to perform independent verifications by QC, electrical
maintenance craft or engineering staff in order to verify and ensure that all safety-related
wiring installations performed via the exempt change (modification) process conformed
to the requirements of the design change documents.
Failure to establish an effective process for independent inspection and verification of
modification activities affecting quality such as field installations of safety related exempt
changes is considered a violation of 10 CFR Part 50, Appendix B, Criterion X
(50-454/455/98004-04(DRS)).
E1.4
Review of Exemot Chanaes and Modifications
10
4
l
a.
Insoection Scoce
.
The team reviewed selected design modification documents, calculations,50.59 safety
evaluations (SEs), and operability assessments. The modification packages were
reviewed for technical adequacy, completeness and field implementation including
testing and modification closure.
d
The team identified a concern which involved licensee failure to ensure that selected
field-installed design change modifications had been properly evaluated, tested,
signed-off as completed and operable prior to placing them in service. The licensee's
process for controlling modifications to ensure adequate post-modification testing and
package closure was weak. The licensee provided the team with a completed list of
modifications that had been partially or fully installed but not fully tested in the field and
in use by operations. The list, which was provided on the exit date, February 10,1998,
included numerous active DCPs (not fully completed in field or tested). The team
identified several modifications that had been physically installed and placed in service,
even though the modification packages were not signed off as completed and
authorized for use by operations. The following modifications were reviewed:
(a)
DCP 8500999 (M6-0-85-0120)-- This safety related modification was originally
installed in 1986. This DCP installed heat tracing on the exposed portions of the
essential service water (SX) chemical feed lines to provide cold weather
protection for the chemical feed lines so that the chemicals would not crystallize
at low temperatures and block the flow. Two chemicals begin to crystallize at
approximately 60*F and freeze at about 20*F. These feed lines are used for SX
system chemical control including acid for PH control, hypochlorite for
microbiological control, and two chemicals used for scale and corrosion
inhibitors. The scale inhibitor provides heat exchanger protection and the
corrosion inhibitor provides long term corrosion protection of piping and
component surfaces. The team reviewed this modification and identified the
following concems:
The licensee could not locate historical data for the period between 1986
.
and 1994 concerning this modification and past work performed on the
chemical feed lines. However, during interviews with system engineers,
the team found that between 1988 and 1992 at least seven work requests
(WRs) were issued to cut out the four SX chemical injection lines and
install new pipe sections because they were found completely clogged
(possibly due to crystallization). Root cause was given in the WRs as
" abnormal wear."
At the time of the inspection, the DCP was open, waiting for completion of
.
testing requirements and package closure. The team determined that
although the modification was installed in 1986 and placed in use, the
modification testing was approved in 1993 and performed unsuccessfully
in 1994. The test was not successful because one of the four
thermostats failed to reset. MWR B10072 (WR940011365) was
11
,
---
,
t
generated on August 1,1994, to correct this deficiency, but was never
implemented in the field. Tne WR940011365 documented on
November 3,1997, that " heat trace had been repaired by unknown
party." The test was re-performed on January 31,1998, following NRC
questioning.
As a result of ultimate heat sink design basis reconstitution in 1994, the
.
i
SX cooling tower (SXCT) basin level was increased. The licensee issued
ECN 000947E, in April 1997, to address the effects of the increased
SXCT basin level. The licensee identified that some of the original
installed heat tracing and insulation were submerged under water,
resulting in degradation of the heat tape and insulation. A decision was
made to remove the insulation and relocate the heat trace. In July 1997
the ECN was completed in the field and placed in use, but was not fully
tested.
Design drawing 6E-0-4030HT09 stated that all four heat trace
.
thermostats for the chemical feed piping to the SX basin should be set to
open above 80*F. FCR F-71531, was initiated December 10,1986 to
change the thermostats set point from 60*F to 80*F to ensure that the
chemicals do not crystallize. The thermostats were recently found to be
i
set in the field at 60*F. Following NRC inquiry into this issue, the set
point change was made (from 60*F to 80*F) in the field on January 31,
1998 (PIF B1998-00500).
(b)
DCP-9201399- dated December 16,1992, " Replace modicon with new updated
hardware / software-current equipment obsolete." WR 940042333-01 replaced
<
the existing Modicon controller with a new controller for the makeup
demineralizer (WM)in May 1995. The package was sent to system engineering
for operational testing in August 1995. Various discrepancies were identified in
1995 between the Modicon program and the logic drawings. Although the
system has been in use by operations, programming problems had not been
resolved at the time of the inspection and operations procedures still needed to
be revised to reflect new programming changes. Finally, system engineering
i
needed to perform exempt change close out activities. The team was informed
that projected date for completing this BOP modification was March 1998. The
team noted that interface problems between engineering, purchasing, vendor
and operations resulted in this system operations enhancement modification not
being completed.
(c)
DCP 9201089 - dated September 16,1992, was initiated (following an NRC
,
l
concern) to add cathodic protection to under-ground H2 gas header OHYO1
l
(from HY farm to station). NRC open item 454/92007-01 documented a concern
l
regarding protection from corrosion of hydrogen gas in under-ground pipes. The
l
inspector was concemed that since the pipe had no cathodic protection, faults
'
and discontinuities in the pipe coating could develop and lead to corrosion of the
pipe with a subsequent hydrogen release causing a fire and explosion hazard.
12
l
l
1
<
,
l
l
i
.
'.
The licensee determined, in 1992, that the level of cathodic protection provided
for the hydrogen piping was unacceptable; it was at .385 volts versus a required
acceptable value of .85 volts. The NRC open item was closed based on
!
licensee commitment to address this safety concern. During subsequent
licensee attempts to address this concern in 1994, a survey showed the pipe as
shorted and not receiving any cathodic protection. In addition, the header pipe
could not be Rcated due to interference from adjacent buried structures. The
j
team was informed that because of the length of time the old pipe was in the
/
,
ground unprotected, an action request was written in January 1998 to replace
!
the pipe,
c.
Conclus10ns
The safety related modifications reviewed by the team were generally adequate.
,
However, the team was concerned that inadequate attention was placed on balance of
I
plant but important to safety modifications.
The team determined that the licensee's failure to take adequate corrective action and
l
ensure that field-installed safety related modification DCP 8500999 (M6-0-85-0120)
had been properly evaluated, tested and signed off as completed prior to placing it in
service, is considered an example of a violation of 10 CFR Part 50, Appendix B,
Criterion XVI (50-454/455/98004-03c(DRS)).
,
E2
Engineering Support of Facilities and Equipment
i
E2.1
Out-of-Tolerance Safetv-Related instrumentation /Comoonent Controls
l
a.
Insoection Scoce
The team examined activities to develop an instrument out-of-tolerance (OOT) trending
program. The team ascertained whether established programs were in place to ensure
I
that OOT instruments were identified, their cause determined and corrective action
i
l
taken to preclude repetition. The review included interviews with appropriate Byron
Station personnel and review of equipment trending printouts.
'
l
l
b.
Observation and Findinas
The team determined that Byron Station personnel could not provide a listing of
safety-related instrumentation that were determined to be OOT for two or more
consecutive calibrations over the past five years. The team did receive a more limited
j
fisting of transmitter trending printouts.
A review of these printouts revealed that there were 37 instances in Unit 1 and 35
instances in Unit 2 where transmitters in safety-related instruments were OOT in two or
more consecutive calibrations. Some transmitters were OOT in as many as four
consecutive calibrations.
13
i
(
Further review of this matter revealed that personnel were not aware of the existence of
'
Corporate Procedure NES-EIC-20.03 " Evaluation Of Instrument Performance" dated
May 5,1997, therefore, the requirements of this procedure were not being implemented
at Byron Station. The procedure stated that if an instrument was consistently founo
outside the administrative limit, the probability was high that the instrument was starting
to fail. The procedure also stated that in order to make a valid determination of an
instruments' degradation, a trend of its performance over time was to be documented.
The procedure required, in part, that for transmitters found to be two consecutive times
OOT, the inspection interval must be decreased; and transmitters found to be three
times OOT in three consecutive calibrations were to be considered misused or failed
and shall be replaced. The team determined that these corrective actions were not
taken for transmitters found in this category,
in response to the teams' concerns, licensee staff stated that implementation of the
corporate NES procedure was under review and had not yet become policy at Byron.
PIF B1998-00462 was initiated to address this concern.
l
The team determined that the licensee failed to implement an effective program to
>
l
address a long standing issue regarding resolution of OOT conditions. A concern
relative to OOT instruments was previously identified in NRC inspection report
454/95011. There was a lack of communication between site engineering and corporate
nuclear engineering on the method for implementation of the standard.
c.
Conclusion
The team concluded that the licensee failed to implement an effective corrective action
i
program to evaluate and address repetitive OOT conditions adverse to quality even
J
though the very same issues were raised in previous NRC inspections both at Byron
!
l
Station (IR 454/95011) and the Zion Station (IR 295/97023).
The team informed the licensee that failure to assure that conditions adverse to quality
are promptly identified and corrected is considered an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-454/455/98004-03b(DRS)).
E2.2 Electrical Cable Imoedance Discrecancy
a.
Insoection Scoce
l
On January 21,1998, Byron Station issued PlF No. B1998-00321, " Cable Impedance
'
Discrepancy." This PIF stated that on January 16,1998, a 10 CFR Part 21 report was
initiated at Clinton Station regarding the use of incorrect cable resistance values in
determining cable tray loadings and voltage drop of cables rated less than SkV. Sargent
and Lundy Standard ESA-102 did not correctly reflect resistance values for tin-coated
copper conductors used at Clinton and Byron Stations.
l
14
l
i
6
b.
Observations and Findinos
The licensee prepared PlF No. B1998-00321 to acknowledge that Byron Station was
-
aware of this problem and to require an operability assessment as prescribed in
BSE 10-1, Revision I," Operability Assessment Procedure. Byron Station continued to
pursue this issue following BSE 10-1 by completing Attachment B of that procedure
'
(LOG No.98-007). Attachment B concluded that the Sargent and Lundy " Evaluation of
the Impact of Using STD ESA-102 Cable Impedance Values in Design Calculations,"
dated November 21,1997, concluded that the conservatism in the assumptions and
parameters in the voltage drop calculations, when considered jointly, more than
l
compensate for the errors introduced using the data in ESA-102. Nonetheless, the
Byron Station review could continue with completion of BSE 10-1, Attachment C
Operability Assessment. The team independently reviewed Sargent and Lundy's
" Evaluation of the impact of Using L D ESA-102 Cable Impedance Values in Design
,
Calculations," dated November 21,1997, and Byron Station Operability Assessment,
)
BSE 10-1, Attachment B, and agreed with their conclusions.
1
The team's evaluation of the licensee's actions considered that the resolution of this
'
issue was very good. However, a weakness was identified in that BSE 10-1,
Attachment C, had no firm completion date. The team observed that the marginal cases
should be bounded and resolved on an expedited schedule.
The licensee provided the E&TS Team Leader, during the Exit Meeting held on
February 10,1998, with a copy of the Action Plan titled "ESA-102 Cable Impedance
Change Impact Assessment for Byron and Braidwood Stations. The action plan
included assessment of impact of cable impedance change on several of marginally
acceptable circuits and on voltage drop and ampacity calculations. This plan scheduled
the final actions to be completed by April 15,1998.
c.
Conclusion
The team concluded the licensee acted promptly and in accordance with the procedures
established to resolve operability issues. This item is considered Unresolved pending
licensee completion of the action plan to assess impact of cable impedance change on
marginally acceptable circuits and further NRC follow up (50-454/455/98004-05(DRS)).
'
E2.3 Assessment of Switchvard
E2.3.1 Walkdown of the Switchvard
a.
Insoection Scoce
As par 1 of evaluation of the SY (switchyard) system, the inspectors walked down the
switchyard and the switchyard control room to assess the material condition of the
equipment. The team observed the material condition of the switchyard batteries and
control cubicles in the switchyard control room.
15
l
.
f
n
i
b.
Observation and Findinas
l
I
The material condition of the equipment in the switchyard control room was generally
good. The team also walked down the switchyard. The team noticed that some relays
,
in the cabinet of Air Circuit Breaker ACB 6-7 were hanging in the form of an arc with the
relay mounting plastic bracket melted by the heat generated by the cabinet heater. PIF
g
No. B1997-03248 was issued by the licensee on September 19,1997, regarding the
poor condition of this ACB cabinet. This PlF stated, in part, that nearly all components
in the cabinet capable of rusting were rusted and the condition was totally unacceptable
by station standards. Failure of these breakers could result in a loss of offsite power. In
addition, the shift supervisor noted on this PlF that the breaker condition was most likely
the result of an inadequate preventive maintenance program.
The licensee's switchyard supervisor stated that these relays were operational at
l
present. Even though this breaker was classified non-safety related, the team
,
determined that more attention should have been paid to the maintenance of these
)
relays, in view of the importance of the switchyard breakers, as loss of offsite power was
l
the most important contributor to the core damage frequency.
I
c.
Conclusion
The team concluded that the switchyard and the switchyard control room were well
l
maintained except for the relay mounts in the breaker cabinets. The team was
I
concerned that the true root cause for the sagging relays has not been determined.
l
E2.3.2 SMtchyard Breaker Maintenance
a.
Insoection Scoce
The team reviewed the licensee's maintenance of the breakers in the switchyard.
b.
Observations and Findinas
.
Te SY wJem was initially placed in the a(2) category under the maintenance rule and
was placed in a(1) category in January 1998, as a result of exceeding performance
l
criteria for switchyard breakers. There were three relief valve failures during 1997 and
l
two in January 1998 on the air blast circuit breakers, as indicated by the station PIFs.
The vendor (Brown-Boveri) maintenance manual (CH-A-109116E) for the type DLFK air
circuit breakers recommended maintenance be done on several components, including
l
safety (relief) valves once every 10 years. However, the licensee had not implemented
'
this vendor recommendation, even though these breakers were much older than 10
years.
The licensee started to replace these relief valves during 1997, due to a requirement by
the State of Illinois to test these valves. As a result of the licensee not installing these
valves correctly, the valves were unscrewing from their air tank fixtures when these
valves relieved pressure. The licensee did not adequately identify the root cause for
16
i
s
.
I
!
these initial failures. The licensee attempted to correct the problem by increasing the
l
length of the mounting nipple. This did not correct the problem and the valves continued
l
to fail until January 1998. The licensee was still investigating the root cause at the
conclusion of this inspection. The inspectors noted that the switchyard should have
I
been placed in the a(1) maintenance rule category during 1997. This was not done
because the SY system engineer did not classify a relief valve failure as a farctional
failure during 1997. This was identified by the licensee and a PIF was issued.
c.
Conclusion
The team concluded that increased attention was needed to improve maintenance of
the switchyard breakers that failed. The switchyard maintenance was considered a
weakness.
'
E2.4
Design Engineering Caoability
a.
Insoection Scoce
The team examined the mechanical technical staff capabilities.
b.
Observations and Findings
The mechanical engineers, directly involved with the team in the discussions of technical
issues, were found to be qualified and experienced in their respective positions.
Further, engineers demonstrated pride and ownership of their respective areas of
responsibilities,
c.
Conclusion
The team concluded that mechanical design engineering capability was generally very
good at the Byron Station.
E2.5 Auxiliarv Feed System Flow Issues
a.
Insoection Scoce
The team conducted an assessment of the status of several auxiliary feed system
suction pressure and flow issues and related system modifications. The related design
and operability issues had been documented in licensee's * Auxiliary Feed Design Basis
Review Team Report," dated December 30,1996. The team reviewed the design
issues, changes and the related documents.
b.
Qbservations and Findings
The report included issues relative to the adequacy of documentation of system flow
capabilities for various accident analyses. The auxiliary feed pump suction trip set
points were also determined by the licensee to be non-conservative for some design
17
t
basis events. The report left open issues on design flow limiting orifices and the final
resolution of the continuing problems related to suction pressure transients. There was
an additional issue regarding updating the updated final safety analysis report (UFSAR)
to reflect set point changes.
The team determined that the auxiliary feed system modifications, operational
adjustments, and related calculations were adequate to address identified issues and
flow problems.
The team noted minor descriptive discrepancies between PSA-B-97-13 and -14
regarding the location at which pump suction pressure was measured (2 feet vs. 3 feet
"above the pump suction on the six inch pipe"), but no significant concerns were
identified. The licensee issued a PlF to correct this discrepancy.
c.
Conclusion
The team concluded that the auxiliary feed system modifications, operational
adjustments, and related calculations were adequate to address licensee's identified
issues and flow problems.
E3
Engineerina Procedures and DocumentatIQD
E31
Plant Modification Administration
a.
Insoection Scopa
The team reviewed corporate engineering guidance and plant-specific procedures and
documentation. In particular, the team reviewed engineering administration procedures
related to plant modifications. This team considered the quality of these procedures
rather than the effectiveness of their implementation.
,
b.
Observations and Findinas
In general, the corporate and plant-specific guidance was evaluated as being very good
in content, providing a sound basis for good plant performance in the area of
engineering modifications. For example, NEP-04-05, Revision 0, issued January 1995,
titled " Design Change Acceptance Criteria," provided concise administrative and
technical guidance. Checklists were included for the different technical disciplines and
for cross-discipline considerations. Key questions were provided that guide engineers in
the development of testing requirements, including construction tests, modification-
specific tests, and final operational tests.
The team found a potential weak area in NEP-04-01, Revision 4, dated March 28,1997.
Section 4.6.6 of that procedure allowed the replacement of some safety related parts
and components with non-exact items with only a " technical evaluation." While the
j
items listed (e.g., gaskets, packing, grease, bolting material, and bearings) were not
I
necessarily critical to ensuring nuclear safety, this section of the procedure could cause
l
,
18
l
\\
-
.
.
I
potential equipment reliability problems. Careful monitoring of such technical
evaluations and assessment of emergent plant problems relative to this less formal
process may be needed.
c.
Conclusion
Engineering procedures and documentation were assessed by the team to be very
good. The team considered Section 4.6.6 of NEP-04-01 to be a potential source of
concern since it appears to encourage a range of non-exact item replacements.
E3.2 Epilure to Uodate UFSAR Section 6.5.1.2.3.1 on Fuel Handlino Buildino Exhaust System
Analvsis Results
a.
Insoection Scoce
The team reviewed information related to UFSAR Section 6.5.1.2.3.i for the Auxiliary
Building Ventilation.
b.
Observations and Findings
UFSAR section 6.5.1.2.3.i included inconsistent data on temperatures with and without
heaters (Case ill and Case IV). The inconsistency was a result of incomplete
information in the UFSAR on initial conditions. While reviewing the related UFSAR
'
information, the licensee discovered that the data had also not been updated to conform
to a 1986 calculation. To address this discrepancy, the licensee issued PIF B1998-
00354, "VA calculation revision results not updated in the UFSAR Section 6.5."
c.
Conclusions
4
The team noted that inconsistent or incomplete information for the VA system design
existed in the UFSAR since at least 1986.
E4
Engineering Staff Knowledge and Performance
,
E4.1
System Engineering Assessment and Activities
a.
Insoection Scooe
The team interviewed selected system engineers and engineering supervisors. The
team reviewed selected system notebooks. The team walked down the switchyard with
the system engineers.
)
b.
Observations and Findings
The team interviewed the system engineers assigned to the switchyard (SY) and the
,
auxiliary feedwater (AF) systems. The system engineer for the SY system had one year
of experience as a system engineer. The system engineer for the AF system had been
19
r
\\
.
a system engineer for seven months. The system engineers interviewed appeared to
be knowledgeable of their systems and of the problems in their systems.
The team reviewed the system notebooks for the SY, Auxiliary Power (AP) and AF
systems. These system notebooks contained system descriptions, UFSAR sections,
industry contacts and description c.,f events on the respective systems. The team did not
identify problems with the system notebooks reviewed. The team noted that the Byron
system engineering handbook stated in section 3.1 that the system manager (system
engineer) is responsible for "being knowledgeable of significant contributors to the
plant's core damage frequency based on PRA for operating and shut down conditions."
However, neither the system engineer (SY and AP systems), nor his group leader were
aware that the loss of offsite power was the most significant contributor to the core
damage frequency.
l
During the last engineering inspection at Byron in December 1995, the NRC identified
1
that detailed guidance and expectations were lacking for system engineers on how to
conduct system walkdowns to identify equipment deficiencies. During this inspection,
3
no conceins were identified in this area.
c.
Conclusion
l
The system engineers interviewed appeared to be qualified for their jobs. Their
experience on the job as a system engineer was low (less than one year) for two of the
system engineers interviewed. The engineer's.PRA knowledge appeared to be minimal.
However, the system engineers were knowledgeable of their assigned systems. The
team did not identify any problems with the system notebooks reviewed.
E4.2 Mechanical Enaineers Technical Knowledae
a.
Insoection Scoce
i
The team selected and evaluated several mechanical modification packages and
calculations in detail and several of the responsible engineers were interviewed.
l
b.
Observations and Findinas
The Byron Station mechanical engineers interviewed during this inspection were
knowledgeable of their technical products. The team assessed the engineering
technical products as appropriately detailed for the issues being addressed. The better
engineering products were often more recent documents produced during the past few
years as compared with those calculations that were several years old.
'
l
All of the Byron Station engineers interviewed were assessed as having a positive
l
attitude toward their work and, thus, contributing to a good nuclear safety culture. They
l
20
L
g
'
- ',
.
- were assessed as being highly motivated and professional. Moreover, the team noted
that Byron engineers communicate readily within their organization and with their.
. corporate counterparts for mutual support.
c.
Conclusion
The team concluded that Byron Station's mechanical engineering products and staff
were generally very good, largely as a result of their positive attitude toward their work,
good communications with each other and interfacing organizations, and a high level of
mutual support.
I
E7
Quality Assurance in Engineering Activities
E7.1
Quality Assurance Audits /Surveillances and Engineerina Assessments
j
a.
Insoection Scone
The team reviewed several Site Quality Verification (SQV) audits /surveillances,
l
Engineering Assurance Group (EAG) assessments and other external assessments, for
l
their scope, depth of and quality of audits and the licensee's follow up of corrective
j
actions for the items identified.
b.
Observations and Findings
The team reviewed the following SQV audits / surveillance in the engineering areas:
QAA-06-97-08
Design Control
l
.
l
QAA-06-97-10
Corrective Action
.
QAS-06-96-002
System Engineering Department (SED) System / program
.
Notebooks
QAS-06-96-022
Electrical breaker Refurbishment
'
.
QAS-06-96-027
Configuration Management Review
.
QAS-06-97-029
CC System design basis conformanco review
.
The quality of these audits /surveillances was generally good. The team reviewed
selected audit / surveillance findings for verification of licensee's follow up. These items
t
4
I
were tracked adequately for satisfactory completion of corrective actions. In addition,
the team determined that field monitoring reports were' excellent assessments of plant
activities. Quality verification surveillances and audits were thorough and detailed with
.
significant findings identified.
An example of a good external audit was the I&C assessment performed in May 1997.
This audit contained some very good findings. The plant response was provided in
June 1997; however, the licensee had yet to generate the NTS items to follow up on the
findings of this assessment.
21
,.
.
l
Some assessments by external auditors contained good findings. An external design
'
control assessment between May 1997 and September 97 was considered very good.
Findings identified in this report were followed up as NTS ltems. However, findings in
the following areas were not being followed up: Operator work arounds; problems with
system notebooks; lack of questioning attitude; lack of proper standards; and
Westinghouse calculation retrievability.
During the last engineering inspection at Byron in December 1995, the NRC identified
design calculation errors which were not identified during the licensee's design review
l
process and a violation was issued. The licensee identified some category 5 and
l
category 4 items relative to calculations in the November 1997 EAG report. However,
the team noted that follow up activities were narrowly focussed and that the number of
calculations reviewed by the EAG in December was not increased.
The team also identified that there was a weakness in the timeliness of the
implementation of Maintenance IPAP Recommendations. The IPAP report was issued
more than a year ago with only 20% of the recommendations completed.
c.
Conclusion
1
The audits / assessments conducted by SQV and outside auditors were done well and
l
included several significant findings. The licensee, generally, followed up the
audit / assessment findings adequately; however, some weaknesses in follow up of
identified issues were noted.
l
l
E7.2 Self Assessments bv Enaineerina Decartments
l
'
a.
Insoection Scoce
!
The team reviewed engineering activities regarding effectiveness in identifying, resolving
and preventing problems. The team reviewed several self assessments conducted by
system engineering and other engineering departments. Additionally, the team
l
evaluated the licensee's process for initial identification and characterization of the
!
specific problems, elevation of the problems to proper levels of management for
i
resolution, disposition of any operability /reportability issues and implementation of
corrective actions, including evaluation of repetitive conditions.
i
b.
Observations and Findinas
The self assessments by system engineering were satisfactory; however, the self
assessments by the design engineering departments needed improvement. No
guidelines were provided for performing self assessments in design engineering and the
)
assessments reviewed were not uniform or well structured. The self assessment files
did not include corrective actions taken to correct any problems identified or the dates
j
when corrective actions were proposed or completed. The corrective actions for some
assessments were shown as closed in the assessment log; but the corrective actions
22
\\
,,
,
were not yet completed, and the self assessments book was not in proper order. One
electrical self assessment was not found in the book.
'
The team noted that the guidelines provided for system engineering self assessments
stated that findings as a result of spot assessments (such as review of system
notebooks, or certification guides for engineers) need not be documented. After the
team pointed out that these reviews were important, particularly in view of some adverse
comments by an external auditor on the inadequacy of system notebooks, the system
engineering supervisor promptly revised these guidelines, to include the requirement of
documentation of deficiencies, if discovered.
The licensee informed the team that a corporate procedure was being developed for self
assessments in engineering. This procedure was expected to provide better guidance
in performing these self assessments. The procedure was to be issued in February
1998,
i
c.
Conclusion
Self assessments conducted by system engineering were effective, however, those
conducted by design engineering need improvement. More guidance was needed for
i
follow up on the findings identified during these self assessments. The implementation
of self assessment in Engineering was considered a weakness. The licensee was
taking action to resolve these concerns.
E8
Miscellaneous Engineering Issues
E8.1
Reactor Plant Shutdown and Cooldown without Pressurizer Heaters
a.
Insoection Scoce
During this engineering assessment, the team determined that the licensee had not
protected pressurizer heaters from fire damage under 10 CFR 50, Appendix R.
Appendix R requires that the licensee must be able to safely shutdown and cooldown
the reactor after a fire. The team examined this issue.
b.
Observations and Findings
The team reviewed procedures and supporting documents related to safe shutdown and
cooldown. The licensee provided several normal and emergency operating procedures
that relied on the availability of pressurizer heaters, but no supporting documents that
addressed operations without pressurizer heaters were provided.
The team focused their review on the licensee's methods of reactor coolant system
pressure control to determine how shutdown and cooldown with no pressurizer heaters
available would be achieved. As a result of inquiries by the team, the licensee
conducted a shutdown and cooldown evolution on their simulator and discussed the
results with the team. The team also interviewed an experienced operator and went
23
f
.
'
,
.
l
through the applicable procedures with him, assessing how the operators would
implement the procedures.
1
Based on these inquiries, the team determined that no engineering studies or computer
codes discussed with or provided to the team during this inspection specifically address
the most appropriate methods for pressure control during shutdown and cooldown
without pressurizer heaters. Likewise, the team determined that the simulator most
likely does not provide sufficient modeling in this area.
Moreover, plant procedures (e.g.,1BGP 100-5, precautions in section D.2,
PRESSURIZER) direct the operators to use backup pressurizer heaters under certain
conditions "to avoid a temperature stratification within the pressurizer that could lead to
a cooldown transient in excess of Tech Spec or Administrative limits." In spite of such
precautions, the Byron Station procedures for shutdown and cooldown did not
specifically mention or address the potentially more severe situation in which operators
might have to cooldown the reactor plant with some or all of the pressurizer heaters not
being available. The procedures provided to the team assumed that the pressurizer
heaters were always available.
The licensee stated that, if current procedures were used for shutdown and cooldown
under the conditions suggested by 10 CFR 50, Appendix R, that the operators would
have to initiate safety injection. This would likely be followed by safety injection
termination at least once before achieving solid plant pressure control. The team noted
that the safety injection procedure focused on pressurizer level control rather than on
pressure control. The team was concerned that without a specific pressure-related
analysis, the intermittent use of safety injection could result in potentially unreviewed
1
consequences for reactor plant pressure. Moreover, the team noted that spray bypass
flow would result in gradual depressurization of the reactor coolant system, making
some kind of pressure-increasing capability necessary for the operators to control
pressure during plant cooldown.
Based on information provided to the team, none of these conditions or consequences
have been addressed for the Byron Station or the Braidwood Station. Nevertheless, this
apparent analysis deficiency is mitigated by the presence of systems and procedures
that could reasonably be expected to protect against significant core damage even if
pressurizer heaters were not available and if subcooling was lost for a brief period of
time.
c.
Conclusion
The team concluded that the Byron Station cooldown procedures have not been
assessed adequately to address the situation in which the pressurizer heaters are not
i
available, including the fire protection safe shutdown and cooldown situation anticipated
'
by 10 CFR 50, Appendix R. Moreover, the team concluded that the pressure-related
consequences of using safety injection intermittently to raise pressurizer level have not
i
been the subject of engineering studies or calculations to date, either for normal or
j
emergency operations.
l
24
k
.
.
n
!
This item is considered an Unresolved item pending NRC follow up and completion of
the licensee's stated commitment to find or develop appropriate technical evaluations
and, where applicable, to revise operating and emergency procedures accordingly.
(50-454/455/98004-06(DRS))
l
E8.2 50.54(f) Items
a.
Insoection Scong
The team attempted to review licensee actions to address 10 CFR 50.54(f) items at
Byron.
,
b.
Observations and Findinas
The licensee could not easily provide the 10 CFR 50.54(f)information requested since
the items were managed by the corporate organization. By the time the licensee
provided the packages for review, the team had no time to review the 50.54(f) items.
I
l
c.
Conclusion
With regard to 10 CFR 50.54(f) items, the team noted that the licensee could not easily
retrieve the information requested. The team concluded that this matter required
increased licensee attention.
1
E8.3 Assignments of Nuclear Tracking items (NTS) Items to Engineering for Resolution
a.
Insoection Scope
The team was informed that engineers were reluctant to accept Nuclear Tracking Items
(NTS) items provided by root cause investigators for corrective action and follow up of
eng;neering issues. The team followed up on this concern.
b.
Observations and Findings
During NRC interviews, the team was informed that root cause investigators have had
difficulty getting engineering to accept NTS items and take responsibility for resolving
issues associated with investigation findings documented in root cause reports. These
reports included NTS items for corrective actions assigned to engineering. The team
raised this issue with engineering management and reviewed selected PlFs and
procedure requirements. Procedure NSWP-A-15, R1," Comed Nuclear Division
integrated Reporting program" Section 6.10.4.1 stated that PORC or CARB
management comrnittee members shall be accountable for assigning adequate station
resources to ensure that corrective actions are completed within established due dates.
Subsequently, on February 5,1998 engineering management conducted a meeting to
address corrective action program issues and initiated various action items to ensure
25
_ __
_ - - _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ _ - _ - _ - _ _ _ -
'
l
.
,
,
1
l
that NSWP procedure requirements for adequate resources and priority are assigned to
address the NTS item concern. The team reviewed the action items and discussed the
proposed actions to address this concern. No additional concerns were identified.
c.
Conclusion
The team was informed that root cause investigators have had difficulty getting
engineering to accept NTS items and take responsibility for resolving issues. The
licensee initiated several action items to address this issue.
E8.4
Review of Previousiv identified Unresolved and Ooen Items
(Closed) Violation (50-454/455/95009-04(DRS)): This violation concerned blocking
open fire doors without a plant barrier irnpairment permit (PBI). Personnel involved
were counseled to management's expectations regarding procedural adherence. The
licensee ensured that the requirements were strictly complied with. No additional
problems were noted concerning this problem. This item is closed.
(Closed) Insoector Follow-uo item (50-454/455/95011-04(DRS)): This item concerned
localized pitting and corrosion on a circulating water (CW) pipe, the normal make up line
to the SX cooling tower. Arc strikes were repaired under Work Request (WR)
960096520. All major piping valve bodies were surface prepped and coated. The
carbon steel riser piping between the riser isolation valves and existing stainless steel
distribution headers is being replaced with stainless steel under DCP 9303506. The
section of the C Bypass Line that passes through the D Riser Valve will be replaced
under WR 970028376. This item is closed.
(Closed) Violation (50-454/455-95011-05(DRS)): The team reviewed information on
improvements that were made in the Byron Station calculation management process to
improve quality. Calculation issues were raised during a previous engineering
assessment, NRC Integrated Inspection Report 50-454/455-95011. The licensee's
response to the NRC was in Byron letter 96-0057, dated February 28,1996. Actions
taken included corrections to specific calculations, general upgrades in calculation
related training and calculation review methods, and in engineer access to design
information. Severalimprovements were made to procedure NEP-12-02," Preparation,
Review and Approval of Calculations." Procedure NEP-12-02BY," Byron Calculation
Site Appendix" has also been upgraded. An additional procedure was planned for
implementation during 1998. In addition, the Engineering Assurance Group was formed
in February 1997 to improve calculation oversight. Guidance for oversight reviews was
included in NES-G-03, " Independent Calculation Overview Review," which has been
upgraded to provide better feedback to the plant engineering staff. These corrective
actions were assessed as adequate to address this issue. This item is closed.
(Closed) Violation (50-454/455-96009-04(DRS)): The team reviewed the licensee's
corrective actions for the failure to have adequate design control measures in place to
ensure that the design basis of the Essential Service Water (SX) System was correctly
translated into specifications and other plant documentation. As stated in Byron letter
26
i
l
l
-
-
___
_ _ -
. . -
.
97-0132, June 13,1997, corrective actions taken by the licensee included revising and
applying ultimate heat sink (UHS) calculations to accommodate the potential operability
impacts of silt accumulation and an anti-vortex box in the service water cooling tower
basin. Based en these revised UHS calculations, the licensee has submitted to the
NRC a Technical Specification change request. The licensee also committed to improve
administrative reviews of new work items and work backlogs and to upgrade
expectations regarding surveillances and design basis knowledge. These corrective
actions are essentially completed. This item is closed.
(Closed) Violation (454/455-96012-06(DRS)): The NRC identified that from
December 29,1996, through December 31,1996, a change in the facility as described
in the Updated Safety Analysis Report was made without conducting a written safety
evaluation. The licensee's corrective actions included: (a) a 50.59 safety evaluation was
completed on procedure 1 BOS RF-1 on January 16,1997, and (b) an UFSAR update
was submitted on October 1,1997. This update included a statement that in addition to
the main control room alarm, the station procedures provide for alternate monitoring in
circumstances where the alarm function on the containment sump is annunciated due to
non-RCS sources. The team verified that a 50.59 evaluation was completed on January
16,1997, and that a change to UFSAR was submitted on October 1,1997. This
violation is considered closed.
(Closed) Violation (50-454/455-97015-04(DRS)): This violation involved failure to take
timely action to submit a license amendment request to reflect changes made to CST
water levels in 1994. The team reviewed Byron letter 97-0315, " Application for
Amendment to Appendix A, Technical Specifications, to Facility Operating License,"
dated December 30,1997. The team considered the Byron letter to be responsive to
the stated violation and related technicalissues. This item is closed.
F3
Fire Protection Procedures and Documentation
F3.1
Pre-Fire Plan Uodate
a.
Insoection Scoce
The team evaluated Byron's pre-fire plan program and implementation.
b.
Observations and Findings
The team identified on February 5,1998, that the pre-fire plan drawings had not been
updated. Changes in the plant design had not been incorporated into the pre-fire plan
drawings. The licensee had updated the written portion of the pre-fire plans in 1997 and
closed NTS Item #454-315-97-004F-01 associated with this update. However, no PIF
had been written to identify that the drawings required an update. In addition, Byron had
no process to identify plant modifications that could effect the pre-fire plans, so that
these changes could be tracked and incorporated into the drawings.
Technical Specification 6.8.1 required that written procedures shall be established,
27
,
_J
___
_
E'
.,
implemented, and maintained covering activities referenced in Fire Protection Program
implementation.
BAP 1100-17, Revision 2, " Implementing Procedure For The Pre-Fire Plans," stated, the
Pre-Fire plans as written are required by, and meet the criteria of 10 CFR Part 50
Appendix R and the commitments of branch technical position CMEB 9.5-1 Appendix A.
In addition, the procedure required that Fire Marshal and Fire Protection Engineer
perform an annual review of the pre-fire plans and sign and date a new pre-fire plan
annual cover sheet.
Following the teams identification of these problems, the licensee documented on PlF
- B1998-00618 that the annual review sheet had not been signed and attached to the
pre-fire plans. The licensee stated that they were unaware of this procedural
requirement for the past 9 years.
c.
Conclusions
Prior to February 5,1998, the requirements of BAP 1100-17 were not implemented in
that a new annual review sheet was not signed and dated for the pre-fire plans and the
pre-fire plans were not maintained to meet the criteria of 10 CFR Part 50, Appendix R,
and the commitments of NRC branch technical position CMEB 9.5-1, Appendix A, in that
the drawings had not been updated for more than 10 years. This was considered a
violation of Byron Station's Technical Specification 6.8.1 which required that written
procedures shall be established, implemented, and maintained covering activities for fire
protection program implementation (50-454/455/98004-07(DRS)) .
F5
Fire Protection Staff Training and Qualification
F5.1
Eite Brigade Oualifications
ingpstion Scoce
he team reviewed fire brigade qualifications.
Findings and Observations
s.
The team identified that no immediate corrective actions were taken for concerns
regarding fire brigade qualifications. Four PlFs (PlF B1997-04081, November 12.1997,
PlF B1997-04579, December 12,1997. PlF B1998-0011, January 2,1998, and PIF
B1998-0098, January 8,1998) were issued with concerns that the fire brigade members
were not qualified. These PlFs were closed without addressing whether the fire brigade
was currently qualified. The licensee stated that they were waiting for the medical van
to visit the site in February and that the personnel would be medically certified following
a complete physicalincluding a treadmill test. The failure to address the problems
identified in the PlFs was a program weakness.
The licensee's medical department had only recently required the complete physical
)
28
, .'
-
,
exam for fire brigade personnel qualifications. Previously, the fire brigade members had
to only pass respiratory certification and pass the annual fire brigade training to be
qualified. The annual training was considered the verification that the person could
perform strenuous activities. The licensee claimed that these two activities met the
annual physical exam requirement. In addition, during this time, the licensee did not
have a formal process to verify that site personnel had passed the medical qualifications
and were qualified to be fire brigade members. As a result, medical conditions that
would disqualify individuals from the fire brigade were not sent to individuals responsible
for updating the fire brigade list.
The medical van was on site the week of February 2-6,1998, to give medical exams to
site personnel. Part of the fire brigade refused to take the treadmill test, because
negotiations between licensee's management and Union officials had not been finalized
for treadmill testing. The licensee disqualified these individuals from the fire brigade.
Following the inspection, on February 9,1998, the licensee issued CAR 06-98-008. The
CAR stated: On February 6,1998, during S&QA Audit QAA CE-98-01, " Fire
Protection," Q&SA identified two Station Fire Chiefs that do not have current fire brigade
qualifications. The CAR stated: The Station does not effectively ensure required fire
brigade training is completed and does not effectively ensure the qualifications of fire
brigade members. A Radwaste Supervisor did not receive or make-up first quarter 1997
fire brigade training, as required by BAP 1100-1," Fire Brigade Program," step C.9.b.
PlF B1998-0098 discussed unqualified fire brigade members prior to the Fire Protection
Audit. At the time of the audit, Radwaste Supervisors did not have current medical
qualifications as required by Procedure BAP 1100-1, step C.9.a. The CAR also stated:
The Station missed the opportunity to identify and correct fire brigade qualifications after
PlF B1998-0098 was written.
Byron Station Operating License, Section 2.F, requires in part, that the licensee shall
implernent and maintain in effect all provisions of the approved fire protection program
as described in the UFSAR for the facility.
In a letter to the NRC on August 31,1981, Byron committed to the following in the Fire
Protection Report: The annual physical will demonstrate that fire brigade members are
capable of performing unrestricted physical activities.
BP 9.5.1 NRC requirement: "The qualification of fire brigade members shallinclude an
annual physical examination to determine their ability to perform strenuous fire fighting
activities."
The Byron Fire Protection Report, considered a part of the UFSAR, Section 5.b,
required, that the fire brigade members have an annual physical which shows them
capable of unrestricted activity.
29
'
, ,'
.
c.
Conclusions
The licensee failed to take corrective actions for identified problems with fire brigade
qualifications. In addition, the tracking of individual qualifications was poor. Also, the
team identified that until February 2,1998, the fire brigade members did not have an
annual physical whose results were used to assess their qualifications for unrestricted
activity on the fire brigade. The failure to conduct the required annual physical exams
was a violation of Byron Station's Operating License, Section 2.F which required that
provisions of the approved fire protection program as described in the UFSAR to be
conducted (50-454/455/98004-08(DRS)).
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspection results were presented to members of licensee management at the exit
meetings on February 10,1998. The licensee acknowledged the findings presented. In
addition, a telephone conference was conducted with the licensee on March 5,1998, to discuss
newly identified technicalissues.
I
30
F
'1
, ' .
,
.
l
PARTIAL LIST OF PERSONS CONTACTED
1
l
Licensee
B. Branson, Q&SA, ISEG Supervisor
B. Carr, E&TS Inspection Database Coordinator
,
B. Cascarano, Supervising Engineer, NES
l
R. Colgiazier, NRC Coordinator
l
P. Donavin, Engineering Design Supervisor
l
T. Gierich, OPS Manager
i
I
B. Jacobs, Electrical MOD
'
P. Johnson, Engineering Support
K. Kofron, Station Manager
B. Kouba, Engineering Manager
!
B. Long, IM Support
R. Mancini, Electrical Lead
K. Passmore, Engineering Program Supervisor
D. Popkins, Ex. Admin. Operations Engineer
B. Renhart, Chief Engineer, NES
B. Wagner, SED Program Manager
NflC
Z. Falevits, Reactor Inspector
N. Hilton, Resident inspector
'
2
e
31
..
,
I
t
INSPECTION PROCEDURES USED
l
Engineering
l
lP 37700
Modifications
'
l
Effectiveness of Identifying and Resolving Technical Issues
l
ITEMS OPENED, CLOSED AND DISCUSSED
1
l
Ooened
50-454/455/98004-01(DRS)
GL 96-01 - Testing of S.R. contacts
50-454/455/98004-02(DRS)
Inadequate design control measures for an
AF Modification
50-454/455/98004-03a(DRS)
DCP 9600148 had not been completed
since May 1996
i
50-454/455/98004-03b(DRS)
Failure to implement an effective program
to resolve long standing OOT issues
50-454/455/98004-03c(DRS)
Modifications in use but not fully
tested nor closed out
50-454/455/98004-04(DRS)
Failure to establish an adequate
independent verification process for Exempt
Changes
50-454/455/98004-05(DRS)
Electrical cable impedance discrepancy
(10 CFR, Part 21)
50-454/455/98004-06(DRS)
Plant Shutdown and cooldown without
pressurizer heater available
50-454/455/98004-07(DRS)
Failure to Update Pre-Fire Plans
50-454/455/98004-08(DRS)
Fire Brigade Not Qualified
Closed
50-454/455/95009-04(DRS)
PBI Not issued for
impaired Doors
50-454/455/95011-04(DRS)
IFl
CW Piping Corrosion
l
32
%-
,;.
.
50-454/455/95011-05(DRS)
Calculation deficiencies
.
50-454/455/96009-04(DRS)
Failure to have adequate design control
measures for SX system
50-454/455/96012-06(DRS)
Failure to perform a 50.59 SE
50-454/455/97015-04(DRS)
Failure to submit a license amendment
request in a timely manner.
33
,.
.
.
.
.. . . . .
.
.
4
)
,;'.
!
LIST OF ACRONYMS USED
i
BAP
Byron Administrative Procedure
Branch Technical Position
Corrective Action Report
!
Corrective Action Review Board
Circulating Water
CECO
Commonwealth Edison Company
Design Basis Accident
Design Change Package
EC
Exempt Change
Environmental Qualification
Engineered Safety Feature
E&TS
Engineering and Technical Support
FMRs
Field Monitoring Reports
Final Safety Analysis Report
IFl
Inspector Foi!cw up item
IP
Inspection Procedure
LER
Licensee Event Report
Loss of Coolant Accident
Logs of 0mce Power
NRC
Nuclear Regulatory Commission
NTS
Nuclear Tracking System
Out of Tolerance
PBI
Plant Barrier impairment
PlF
Problem identification Form
QAA
Quality Assurance Audit
Quality Control
Q&SA
Quality and Safety Assessment
Safety Evaluation
SQV
Safety and Quality Verification
Structures, Systems, and Components
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved item
Violation
Work Request
EAG
Engineering Assurance Group
.
l
34
4
, ;i
.
!
Partial List of Documents Reviewed
Byron Fire Protection Report, Amendment 13, December 1990
PlF #B1997-04081," Fire Brigade Chief's Qualifications"
PlF #B1997-04579,"PIF Question Not Answered"
PlF #B1998-00011 "First Two PlFs Do Not Answer the Question"
PIF #81998-00098," Unclear Fire Brigade and Hazmat Responder Qualifications"
PlF #B1998-00618," Pre-Fire Plan Annual Review"
Byron Station Pre-Fire Plans, Revision 1
10 CFR 50.59 Screening Evaluation T3-96-0075
DCP #9600148," Mounting Details A Diesel Battery Racks"
Calculation #7.16.10.2, " Battery Rack Supports"
Letter," Byron Station Units 1 and 2 Fire Protection," August 31,1981
Safety Evaluation Report, February 1982
SWP-A-15 " Comed Nuclear Division integrated Reporting Program," Revision 1
CAR 06-98-008," Fire Brigade Procedure Adherence"
Comed Overview of the Medical Evaluation Process / Medical Assessment of the Structural Fire
Brigade
BAP 1100-17," Implementing Procedure for the Pre-Fire Plans," Revision 2
DCN 9700473, ECN BYR-001015M, " Installation of shaft seal and new type of bearing sealin
order to reduce oil leakage in the Aux. Building HVAC exhaust fans," Revision 0, approved
l
September 5,1997
DCP 8701382, " Resolve AFW suction Standpipe Overflow Problem"
DCP 9400043, PIF B1997-05059," Installation of HEPA Filters without Technical Evaluation,"
dated December 22,1997
DCP 9600228," Install Vibration Monitoring Equipment on the VA Supply and Exhaust Fans,"
exempt change documentation and drawings
DCP 9600404/5, Install AF Pump Diesel Drip Pans, exempt change documents dated
December 11.1997
DCP 9700400, "B AF Pump Engine Fuel Shutoff Solenoid," Technical Evaluation 97-170,
i
Revision 0, approved July 31,1997
DCP 9700426, " Valve handle Replacement," Technical Evaluation 97-182, Revision 0,
approved, December 11,1997
DCP 9700473, " Replace VA Bearing Seals with Ones that Have O' Rings"
DIT-BB-EXT-0135 (S&L letter CAN-272 of March 3,1992) providing design information on AF
pump suction piping standpipe and loop seal modification M6-1/2-87-168; calculations AF-081,
AF-082, and AF-91; ECN 06-00227M and ECN 06-00222S; ECN 06-00259
EMD-034501, Addendum M, " Qualify a vent line detail to be added to subsystem 1 AF03
between the 1 AF017A/B and 1 AF006A/B valves," Revision 0, approved May 31,1996
NED-M-MSD-9, Byron Ultimate heat Sink Cooling Tower Basin Temperature: Part IV,"
Revision 4, approved March 17,1997
NED-M-MSD-11, " Byron Ultimate Heat Sink Cooling Tower Basin Temperature Calculation:
Part V, Bypass Operation," Revision 0, approved December 17,1991
l
NED-M-MSD-14, " Ultimate Heat Sink Cooling Tower Basin Makeup Calculation," Revision 4,
l
approved November 5,1997
35
i
.
, ;'6
l
l
SR 97-092," Operability Assessment #97 035: AF/CO/FP Interface," approved July 9,1997;
including calculations on seismic and HELB issues raised with regard to AF diesel pump air
intakes
l
PSA-B-95-06," Byron /Braidwood Maximum AFW Flow for Revised SGTR Analysis," Revision 0,
dated April 6,1995
I
PSA-B-96-05," Analysis of AFW Pump Suction Transients for Byron and Braidwood Stations
Using RELAPM3," dated June 30,1997
l
PSA-B-97-10 " Byron /Braidwood AFW Flow Orifice Verification," Revision 2, dated
'
September 3,1997
l
PSA-B-97-13, " Evaluation of CST Vortices for Byron and Braidwood Stations," dated
!
December 17,1997
l
PSA-B-97-14, " Evaluation of New CST TS Levels for Byron and Braidwood Stations,"
I
Revision 0, dated December 17,1997
!
PSA-B-97-18, * Byron /Braidwood AFW Flow for AF005A-H Modification," Revision 2, dated
December 5,1997
PSAG-138,"Available NPSH for AF Pump When Supplied from SX System," Revision 0, dated
February 20,1989, " Auxiliary Feed Design Basis Review Team Report," dated
December 30,1996
1BEP ES-0.1, " Reactor Trip Response," Revision 1C, WOG-1B, approved January 21,1998
l
1BEP ES-0.2, " Natural Circulation Cooldown," Revision 1 A, WOG-1B, approved October 17,
1997
1BEP ES-1,1, "Si Termination," Revision 1, WOG-1B, approved April 12,1995
1BEP ES-1.1, "Si Termination," Revision 1, WOG-1B, approved January 26,1998
1BEP-0, " Reactor Trip or Safety injection," Revision 1C, WOG-1B, approved January 21,1998
i
1BEP-1," Loss of Reactor or Secondary Coolant," Revision 1, WOB-1B, approved April 12,
i
1995
,
1BGP 100-5, " Plant Shutdown and Cooldown," Revision 27, approved January 24,1998
!
BAP 1310-8, "Special Procedures / Tests / Experiments," Revision 12, approved May 15,1997
l
BAP 1600-1, " Action / Work Request Processing Procedure," Revision 41, approved May 23,
1997
BAP 1600-7, " Minor Changes Which Do Not Change Function," Revision 8, approved
January 27,1993
BAP 1600-14," Processing and Control of Minor Work Activities Completed as Action Requests,
Minimal Work Request, or Pre-Reviewed Work Requests," Revision 7, approved August 27,
1997
BAP 1610-8, " Processing Byron Station Design Changes," Revision 16, approved in
October 1997
l
BAP 1610-9, " Engineering Requests," Revision 3, approved April 30,1996
'
BAP 500-19," Byron Conduct of Engineering," Revision 4, approved March 1,1997
BSEG-7," Roles and Responsibilities of the Byron Engineering Assurance Group," Revision 1,
undated
i
Byron letter 97-0315," Application for Amendment to Appendix A, Technical Specifications, to
Facility Operating License," dated December 30,1997
EAG November Report 1997, dated December 8,1997, David W. Berg
NEP-04-01, " Plant Modifications," Revision 4, dated March 28,1997
j
i
NEP-04-02, " Exempt Changes"
NEP-04-05," Design Change Acceptance Criteria," Revision 0, issued January 1995
36
- 6
L'
NEP-09-02," System Performance Monitoring and Analysis," Revision 0, dated June 2,1997
NEP-12-02, " Preparation, Review, and Approval of Calculations," Revision 5, issued June 30,
1997
NEP-12-02BY, " Byron Calculation Site Appendix," revision 1, issued June 12,1997
NSWP-A-04, "10CFR50.59 Safety Evaluation Process," Revision 0, dated January 31,1997
NSWP-A-13," Root Cause Investigation Procedure," Revision 1, dated May 5,1997
NTS 454-200-94-05400-02, " Final Resolution to Suction Pressure Trip"
NTS 454-230-97-SCAO00028-01,1B Diesel AF Pump Overcrank Lockout, July 17,1997
l
NTS 454-400-96-ESS-J02-01, " Design Flow Limiting Orifice"
NTS 455-200-97-SCAQ00014-01,2B Diesel AF Pump Overcrank Lockout, May 13,1997
OSR 97-178, " Proposed Changes to Technical Specifications Minimum Condensate Storage
Tank Level and Auxiliary Feedwater," dated December 18,1997 (see PIF B1997-03504)
f;PP 97-045, " Auxiliary Feed Flow Verification," special test procedure, approved January 9,
1998
DCP No. 9400210 " Revise Motor Driven auxiliary feed water pump circuit for change over of
suction source"
DCP No. 9400427 " Revise Auxiliary Feed low suction pressure alarm, SX swapover and pump
trio set points"
DCP No. 9500367 " Revise the trip settings for molded case circuit breakers for MOVs 1
AF013 A-H"
Modification No. M6-0-92-009 C1 " Installation of overload protection and trip for auxiliary
building chiller motors"
DCP No. 9700391 " Add a filter to the motor driven auxiliary feed water pump suction pressure
circuit"
l
1
l
l
l
37